Oil displacement process



F IF 7%] 2 OR 3 9 3&3 9 68b R. J. BLACKWELL ET AL 3,363,685

OIL DISPLACEMENT PROCESS Jan. 16, 1968 Filed Dec. 21, 1964 5 Sheets-Sheet 1 SOLVENT (25% IPA, 25% 6 SINGLE PHASE REGION FIG. I.

AT ATMOSPHERIC PRESSURE ROOM TEMP.

BRINE IPA F'G 2 SINGLE PHASE REGION AT ATMOSPHERIC PRESSURE ROOM TEMP.

A. 0 v 0 N9 vit iw MN on. a

. INVENTORS. ROBERT \LBLACKWELL, FRANK A.MORGAN]I[ BY JOE lh/Z/IL:E{KER,

BRINE ATTORNEY.

Jan. 16, 1968 R J BLACKWELL ET AL OIL DISPLACEMENT PROCESS 5 Sheets-Sheet 21, 1964 *INPUT Filed Dec.

FIG. 9.

MIDDLE BANK FIG.

PHASE BEHAVIOR OF THE SYSTEM SINGLE PHASE REGION I PA co a5 |5% BRINE ROOM TEMP.

HYDRO CARBON INVENTORS. R06 5 a 1' J. BLACKW ELL, F R ANK A moRsAmIlI,

oz K. HEIZ: ac KE 3,

Jan. 16, 1968 R, BLACKWEL L ET AL 3,363,685

OIL DI SPLACEMENT PROCES S Filed Dec. 21, 1964 5 Sheets-Sheet 4 |PA+co EFFECT OF wATER SALINITY a LEGEND: I

ON PHASE BEHAVIOR A TIE LINES" SALT CONTENT OF WATER 700 PSI V A. v

A 2.1 ROOM TEMP.

DISTILLED I AROMATIC WATER a E HYDROCARBON BRINE SOLVENT IPA co;

o FIG 5 IPA +c0 (a5 I5/o) PHASE BEHAVIOR or THE ARoMAT HYDROCARBON gys SOLVENT A DISTILLED WATER 700 PSI ROOM TEMP.

9w a to; A

em 0 6 e DISTILL'ED AROMATIC WATER HYDRO CARBONS INVENTORS. ROBERT J. BLACKWELL, FRANK A. moReAmIlI,

Jan. 16, 1968 R. J. BLACKWELL ET AL OIL DISPLACEMENT PROCESS 5 Sheets-Sheet Filed Dec. 21. 1964 FIG. 7. I

' EFFECT OF BANK SIZE cons 3/a"x 3/e"x 8 OIL RECOVERY FLOODING SEQUENCE,

|o% P.v. CARBONATED WATER 2. AROMATIC SOLVENT A BANK 3. EQUAL SIZE IPA- CO BAN'K O s w BANK s|zE,% PORE VOLUME BRINE] PRODUCTION HISTORY- 39% BANK BRINE OIL I MATIc SOLVENT A j OF AROMATIC SOLVENT A AND IPA-C02 IN 3/8"X3/8"X8'BEREA cone BOJBRINE L Ema W -E K K NCAC EAG V MH B W .M J .E T RK EN A 0R RF PORE VOLUMES INJECTED FIG. 8

JE BY 2% United States Patent 3,363,685 01L DISPLACEMENT PROCESS Robert J. Blackwell and Frank A. Morgan HI, Houston, and Joe K. Heilhecker, Bellaire, Tex., assignors, by mesne assignments, to -lEsso Production Research Company, Houston, Tex., a corporation of Delaware Filed Dec. 21, 1964, Ser. No. 419,843 15 Claims. (Cl. 166-9) ABSTRACT OF THE DESCLUSURE The present invention relates generally to the recovery of oil from subsurface reservoirs. In particular, it concerns the recovery of reservoir oil by a displacement process which utilizes a series of water-driven banks as the displacing media. More particularly, a prefiood bank of carbonated water is introduced into the reservoir followed by a bank of aromatic hydrocarbon solvent miscible with the reservoir oil which, in turn, is followed by a bank of oxygenated hydrocarbon miscible with the arcmatic hydrocarbon and water in the reservoir. These banks are followed by driving water. Preferably, the carbonated water and the driving water each contain about 2 to 3% by weight salts. As used herein, the term salt means salt compositions typical of natural reservoir brines. It is preferred to saturate the preflush carbonated water with an excess of carbon dioxide at the temperature and pressure at the sand face in the well bore. The aromatic solvent viscosity is preferably adjusted to make it approximately the same as that of the driving water. The viscosity of the oxygenated hydrocarbon is also preferably adjusted to that of the driving water. The aromatic hydrocarbon desirably contains over 80% aromatics and is preferably a refinery by-product boiling within the range of about 350 F. to about 700 F.

This invention is especially concerned with tertiary oil recovery; that is, the recovery of oil left in a reservoir already swept by water. However, the method of the invention is also useful in secondary recovery operations.

It is possible for fluids which are miscible or which can become miscible with the reservoir oil to displace all of the oil from the oil-containing portions of the reservoir contacted by such fluids. In practice, a bank or slug of these more costly, oil-soluble solvents is first introduced into the reservoir before the cheaper, scavenger fluids which are miscible or which can become miscible with the oil-miscible solvents are introduced into the reservoir.

Studies have shown that the displacing fluids should preferably have the following properties:

(1) The viscosity of the displacing fluid should be equal to or greater than the viscosity of the displaced fluid in "ice order to reduce channeling or viscous fingering of the displacing fluid and by-passing of the displaced fluid which is a result of such channeling.

(2) In low permeability reservoirs and/ or in reservoirs with low angles of inclination (dip angles) the displacing fluids should have densities as near as possible to the densities of the displaced fluids in order to reduce the elfect of gravity segregation which promotes channeling of the displacing fluid along the top or bottom of the oil-bearing strata; and I (3) The quantity of the more expensive components in the oil-miscible, solvent bank should be minimized and a minimum effective volume of the oil-miscible solvent between the displaced oil and the displacing, scavenging fluid, should be used.

The low viscosities and low densities of light, oil-miscible hydrocarbons such as methane (C ethane (C propane (C and butane (C etc. or mixtures thereof used to displace reservoir oils compared to the viscosities and densities of reservoir oils results in channeling and viscous fingering of these displacing miscible hydrocarbons through the reservoir oils. The poor vertical conformance and areal pattern efliciency resulting from the use of such hydrocarbon solvents give an ineflicient sweep of the reservoir, although all oil is recovered from the region contacted when conditions of miscibility are met.

The sweep efi'iciencies for oxygenated hydrocarbon solvents such as isopropyl alcohol (IPA), tertiary butyl alcohol (TBA), and propyl alcohol, which are or can become miscible with reservoir oils and with reservoir resident waters are much higher than those for the light, oil-miscible hydrocarbon solvents, C to C etc. mentioned above because the viscosities of the alcohols are closer to and generally greater than the viscosities of most crude oils and resident waters; and the density difference of the alcohol solvent-crude oil system is less than that for the light hydrocarbon solvent-crude oil system. Consequently, viscous fingering is less severe or even absent and gravity segregation is much less a problem in the oxygenated hydrocarbon flood system than in other systems. However, a disadvantage in the use of oxygenated hydrocarbons is that the equilibrium relations between most of them, as for example, IPA, crude oil and resident waters are such that small concentrations of water in the alcohol and particularly, waters containing small quantities of salts; e.g. NaCl, MgCl etc., can prevent or inhibit the attainment of desired miscibility. In addition, the high cost of the oxygenated hydrocarbons which are or can become miscible with the oil prohibits their use in many reservoirs where otherwise their use would be technically feasible.

The present invention uniquely combines an aromatic solvent bank and an oxygenated hydrocarbon solvent bank system in a manner that retains the advantages but overcomes the disadvantages in use of the oxygenated hydrocarbon bank system above. In accordance with this invention, two solvent banks are employed. A carbonated water bank, preferably saturated with carbon dioxide is injected ahead of an aromatic solvent bank and an oxygenated hydrocarbon solvent bank. The carbon dioxide is absorbed from the injected water which swells the oil and makes it less viscous. In this manner, a better volumetric sweep of the sand is obtained. In addition, the presence of CO improves the phase behavior between the oxygenated hydrocarbon and the aromatic solvent making the oxygenated hydrocarbon more soluble in the aromatic solvent than in the Water. The aromatic solvent bank follows the carbonated water bank. It is preferably composed of an aromatic refinery by-product containing over 80% aromatics and, if necessary, blended with toluene or other less viscous aromatics to reduce its viscosity to about 1 cp. which is the viscosity of the lead carbonated bank and the viscosity of the following oxygenated hydrocarbon bank. The crude oil and a portion of the resident water are displaced by the aromatic solvent bank. Thus, for example, about onehalf of the resident oil containing the absorbed CO and about one-half of the resident water are displaced by the aromatic solvent bank. The next bank contains an oxygenated hydrocarbon plus carbon dioxide. This bank is preferably about 85% by volume isopropyl alcohol and about 15% by volume carbon dioxide. The alcohol bank functions to displace the aromatic solvent bank and the remaining resident water. Another feature of the invention resides in the salinity of the water ahead of and behind the oxygenated hydrocarbon bank. Phase behavior studies and laboratory displacements of oil from consolidated rock show that an optimum salt content of about 2 to 3% by weight exsists for the water. Therefore, water of about 2 to 3% by weight salt is injected into the reservoir ahead of and behind the alcohol bank to improve efiiciency of the oil displacement.

Thus, a primary object of the present invention is to improve the displacement efficiency of water-driven oxygenated hydrocarbon banks. A further important object of the present invention is to improve the displacement efliciency of aromatic hydrocarbon and oxygenated hydrocarbon banks introduced in sequence into the oil reservoir by using water ahead of and behind these banks that contain critical amounts of salts. Another object of the present invention is to provide an improved oil recovery process using a series of banks, one of which is a highly aromatic hydrocarbon bank. An additional object of the present invention is to improve oil recovery by providing optimum miscibility between reservoir oil, aromatic solvent, oxygenated hydrocarbon solvent, and Water. A further object is to provide an improved oil recovery process in which is employed the lowest concentration of oxygenated hydrocarbon to achieve the greatest miscibility between reservoir oil, aromatic solvent, oxygenated hydrocarbon solvent, and water phases. Another object of the present invention is to improve on oil-displacement processes using oil and water solvents by employing an optimum salt concentration for water ahead of and behind the solvent banks. Also, an object of the present invention is to lessen the viscosity of the reservoir oil and improve the phase behavior between the oxygenated hydrocarbon solvent and the aromatic solvent used as displacing media by adding carbon dioxide to a prefiood water bank.

The above objects and other objects and advantages of the invention will be apparent from a more detailed description thereof when taken with the drawings wherein:

FIG. 1 is a ternary phase diagram of the system 75% IPA, 25% C -crude oil A-brine;

FIG. 2 is a ternary phase diagram of the system IPA- crude oil B-brine;

FIG. 3 is a ternary phase diagram of the system 85% IPA plus CO -aromatic hydrocarbon solvent A- brine;

FIG. 4 is a plot of data illustrating the alcohol bank size required for miscible displacement of oil from a permeable sand in a stratafied reservoir for different length systems and different critical concentrations of alcohol in the banks;

FIG. 5 is a ternary phase diagram of the system 85 IPA plus 15% Co -aromatic hydrocarbon solvent A- distilled water;

FIG. 6 is a ternary phase diagram of the system 85% 4 IPA plus 15% cO -aromatic hydrocarbon solvent A- distilled water or brine 2.7% salt;

FIG. 7 is a plot of data illustrating the effect of bank size on oil recovery;

FIG. 8 shows the production history for the experiments illustrated by the data of FIG. 7; and

FIG. 9 is a schematic representation of a cross-section of the earths subsurface illustrating the process of the invention.

The nature of this invention can be better understood by reference to the figures. An equilibrium phase diagram for the system, alcohol-rich solvent (75% by volume IPA and 25% by volume C crude oil A (38 API asphaltic crude oil) and brine (a synthetic field brine containing 2.7% salt) is illustrated in FIG. 1. In this system miscibility between the three phases is achieved only in a small region, M, near the apex of the diagram. In a similar system, but using a very light crude oil (46 API crude oil), designated crude oil B, and IPA alone undiluted with pentane, the single phase region M is larger, as seen in FIG. 2, than that obtained with the denser, more asphaltic oils, but it is still a relatively small portion of the ternary diagram. Through the sequence of banks used in the process of this invention, better displacement is achieved than with most other crude oil-solvent systems because of the larger, single-phase regions shown on the ternary diagrams (see FIG. 3).

The displacement of crude oil by a bank of aromatic hydrocarbon solvents in accordance with the practice of this invention materially improves the displacement efiiciency of waterdriven alcohol banks in the reservoir.

The importance of displacing the crude oil by a bank of aromatic hydrocarbon solvent is illustrated quantitatively in FIGS. 1 to 3. The points P on FIGS. 1 to 3 are termed the critical concentration; i.e., the alcohol concentration level which must be exceeded to alway have a single phase. These critical concentrations are 92%, 72% and 64% for the crude oil A, crude oil B, aromatic alcohol and water systems illustrated in FIGS. 1 to 3. Lower critical concentrations of the alcohol imply a greater water tolerance before miscibility would be lost in the reservoir.

FIG. 4 illustrates the importance of having low, critical concentrations of alcohol. In this figure are shown the alcohol bank sizes required for miscible displacement of oil from a permeable sand in a stratified reservoir calculated for systems with critical concentrations of alcohol of 0.85, 0.75, and 0.65. As seen in FIG. 4, in a 500-foot long system, lowering the concentration from 0.75 to 0.65 lowers the alcohol bank size required from 7.1% to 3.2% pore volume. Profitable application of an alcohol flood is dependent on the bank size of alcohol required to achieve a given recovery. It is apparent, then, that lowering the critical concentration by the step of displacing oil with an aromatic hydrocarbon solvent, as practiced by this invention, makes the use of water-driven alcohol banks practical for all recovery operations.

The salinity of the water ahead of and behind the alcohol bank is another important feature in practical oil recovery operations. It has been found through phase behavior studies and through laboratory displacements of oil from consolidated rock that an optimum salt content of about 2 to 3% by weight in the water exists. If the water which is displaced by or which displaces alcohol contains as much as 10% salt, then poorer displacement of oil results than if the water which comes out in contact with alcohol contains the optimum 2 to 3% salt. Therefore, if the reservoir brine contains large amounts of salt, the solvent banks in the practice of the present invention should be preceded by a bank of water containing 2 to 3 by weight salt.

A series of displacement experiments were conducted in 3-foot long, 2 inch diameter sandstone cores to illustrate the importance of the optimum salt content. In each experiment, the core was initially saturated with brine, flooded to connate water with crude oil, and then water-flooded to a residual oil saturation of 42%. The resident water contained 10.7% brine. The results of these experiments are tabulated in the following Table I:

6 ment described for Table I. The results of these experiments are tabulated in the following Table II:

TABLE II.EFFECT OF BANKS OF CARBONATED WATER ON RECOVERY OF CRUDE OIL A Bank Recovery, Vol. Exp. Size, Percent TABLE I.EFFECT 0F SALT CONTENT OF WATER 0N No. Bank Material Pei-cent RECOVERY OF CRUDE 01L A Pore Volume Oll Solv. IPA

at arat- 1 annex/sale a No. Bank Material Pi rgreent Carbonated Volume Oil Solv. Ale. 1 74h Carbonated Water 10 3 Carbonated Water... 10 1 f zzw g gg g8 Aromatic SolventA... 25 }so.2 60 65.3

IPA-C02 (85% IPASI 2o 1P New (85% IPA) 25 2 7% Brine 100 2 $258K ilfiifiiji 38 [78.8 48.3 46 As seen in Table II, oil recovery is 80.2% of the residual Brine 100 Oil in Exp. No. 3 whereas only 73.1% of the residual oil 3 Aromatic SolventB 30 i d E N 1 h th I t t IPA-CO2 (85% 20 58.4 60.6 67.9 1s recoveie 1n xp. 0. w en e vta er con ains no 105% Brine 100 C0 Curiously, adding CO to the Water used to drive the alcohol, lowered recovery to 69.9% in Exp. No. 2. Full strength brine components (p.p.m.): Calcium, 2,972; Chloride: Thus, in m5 Practice Of the method 0f the invention, only 63,825; Sodium, 9 Magnesium, 1:051; 13311111, 111; Sulphate: the prefioodwater contains carbon dioxide. Preferably, Carbonate 0; H003 the prefloodwater contains an excess of carbon dioxide above that required for saturation in order to achieve a sizable reduction in the viscosity of the oil.

The data of Table I Show that thleetteh of a 9 Pete Miscible displacement of a viscous, asphaltic oil, ac- Vohtme bank of 17% ht'ihe ahead of the arefhatte Solvent cording to the method of the invention, is illustrated by B and the alcohol banks: and following wlth the 27% 30 the data shown in FIG. 7. These data were obtained using hlihe yielded a greater eh recovery than was Obtained a %-inch square piece of well consolidated berea sand- Wheh 107% hrthe was eehtaeted by the alcohol- Also stone 8 feet long. The sandstone was coated with plastic it is to be noted that oil recovery was 81.5% when 2.7% and Diaced under a confining pressure of about 1,000 brine Preceded and followed the alcohol 78-55% when p.s.i. l'he rock was prepared to contain a residual oil 2.7% brine only followed the alcohol, and 58.4% when 35 saturation using crude oil A of FIG 1 by wateriiooding 107% brine came in Contact with both the front and before each solvent flood. The four solvent floods conhack of the alcohol hahkducted are plotted in FIG. 7. In each case, a 10% pore Further, if the Wa er ahead of and bfihind the alcohol volume bank of carbonated brine was injected ahead of bank contains too little salt, poor phase behavior is noted. the Solvent Bank siZes of 50, 393 331) alid 250% pore The data in 5 are for the system 85% IPA Phls 15% 40 volume composed of equal-sized banks of aromatic solvent CO aromatic hydrocarbon solvent A, and distilled water and were used to displace the Oil It is Seen in at 700 p.s.i. and 72 F. Note that the tie lines have a nega- FIG 7 that when bank siZes exceed 37% pore voiume, tive slope which indicates that alcohol is more soluble in an of the Oil soivgnt and aicchoi are displaced by the water than in the aromatic solvent. The behavior of the driving waterf Also w bank sizes adequate for misci tie lines in FIG. 5 is contrasted with those in FIG. 3 for biiity in thiS giooi ioiig Column were used Separate banks a similar system but with the water containing 2.7% salt. of Oii, aromatic Solvent, and aicohoi were produced in In the System containing 27% lt in the water as Seen sequence as shown in FIG. 8. The production history ilin FIG 3, the tie lines have a peslttve e h the top of lustrated in FIG. 8 indicates that miscibility was achieved the hthodal curve is approached whteh thdleates a Pref in the displacement process. It is to be noted that bank once for solubility of alcohol in the aromatic solvent siZ85 of 37% pore Volume Coiiid not be used profitably in P cehseqhehtty better displaeemeht e eh would be field operations. In field operations where much larger expected with 2.7% brme than with distilled water. An distances are involved than in the 8400i core aicohol optimum salt content, then, of 2 to 3% exists for the best bank Sizes of 2.5 to 4% new volume would be directive displacement of oil for practicing the method of this inin recovery of Oil (see i 4) venti n- The effectiveness of the method of this invention in 6 lhhstrates another Important feature of the miscibly sweeping a reservoir pattern is demonstrated method of this invention, the inclusion of CO in the with the dam Shown iI1 the foiiowing Table III: water injected ahead of the solvent banks. CO in the water bank improves the displacement of oil in two Ways. TABLE Ill-RECOVERY or OIL FROM A s-sro r MODEL First, CO is absorbed from the injected water swelling the oil and making it less viscous. Thus, a better volu- Bank Size, Reeovery,Vol. Percent metric sweep of the sand is obtained. In addition, the 233; presence of CO improves the phase behavior between Volume 011 Solv- IPA the alcohol and the aromatic solvent making the alcohol more soluble in the aromatic solvent than in the water. gig 33-3 2% Referring to FIG. 6, the solid line is a tie line for the 50 71.3 79:0 79

system aromatic hydrocarbon solvent A, IPA and 2.7% brine, while the dotted lines are for the system 85% IPA plus 15% CO aromatic hydrocarbon solvent A, and 2.7% brine.

Other experiments were performed to illustrate the effect of adding CO to the bank of water injected ahead of the aromatic and alcohol solvents. The cores were prepared in the same manner as they were for the experiflooding before each solvent flood. The solvent floods were conducted by injecting a 10 pore volume bank of carbonated water followed by equal-sized banks of aromatic solvent A, and IPA-CO and finally, driving the alcohol bank with 2.7% brine. As seen in Table III, recoveries of 44.5, 60.3, and 71.3% of the residual oil left by water for the 20, 35, and 50% pore volume banks composed of equal volumes of aromatic solvent A and alcohol were achieved.

The operation of the invention, as illustrated in FIG. 9, comprises introducing into a watered-out reservoir to through an input well 11 a first bank 12 of water saturated with CO followed by a middle bank 13 of aromatic hydrocarbon solvent followed by a third bank 14 of alcohol solvent and C0 The third bank is followed by a displacing, scavenging water drive, designated 15, which moves the banks 12, 1.3, and 14 through the reservoir to the output well 16, through which the reservoir oil displaced by the aromatic and alcohol solvent banks is produced. When necessary, the carbonated water bank is preceded by a bank of water having a salt content of 2 to 3% to adjust the water contacted by the carbonated water bank to this critical salt concentration. The carbonated water bank and the driving water also preferably contain a salt concentration of about 2 to 3% by weight.

These experimental data were obtained with crude oil A, an asphaltic 6 -cp., 38 API crude oil, which exhibits the phase behavior shown in FIG. 1 with IPA and brine,

Crude oil B, which is a parafiinic 46 APT, 1.4 cp. oil, exhibits the phase behavior shown in FIG. 2. Recovery of crude oil B is compared with recovery of crude oil A by the method of this invention in the following Table IV:

TABLE IV.COMPARISON OF RECOVERIES OF DIFFER ENT CRUDE OILS BY WATER-DRIVEN SOLVENT AND ALCOHOL BANKS Recoveries of the aromatic solvent A and the alcohol are also compared in this table. The experiments for the data of Table IV were conducted in 3foot long, 2-inch diameter sandstone. The initial conditions were: 45% by volume residual crude oil A saturation; 28% residual crude oil B saturation. The sandstone cores were prepared as in previously described experiments.

Aromatic Solvent A is a mixture of 46% by volume toluene and 54% by volume of a refinery byproduct stream designated for purposes herein as Solvent 1. S01- vent I contains aromatics by volume in the amount of about 30% benzenes (C H indanes naphthalenes (C I-I and 2% tetrahydrophenanthrenes (C H2 14 It boils in the range of from 385 to 586 F. and has an aromaticity of 88.3%.

Aromatic Solvent B, used in the experiments, also includes a highly aromatic refinery by-product designated herein as Solvent II. The aromatic composition of this material is by volume about 11% benzenes, 12% indanes, 3.5% indenes (C H 31% naphthalenes, 15% tetrahydrophenanthrenes, 6% fiuorenes (C I-I and 5% phenanthrenes (C H It boils in the range of 400 F. to 700 F. and has an aromaticity of 83.1%.

Other refinery by-products, preferably having over 80% aromatics, may be used in the process of the invention. Results of experiments with other aromatic refinery by-products are shown in the following Table V, along with the results of experiments using Solvents I and II:

TABLE V.COMPARISON OF OIL AND SOLVENT RE- OOVERIES WI'III VARIOUS AROHATIO SOLVENIS Volume Recovery, Vol.

Percent Percent Solvent System Aromatics in Solvent System Oil Solv. Alc.

54% Solvent I+46%Toluene (Sol vent A) 93. 6 80. 2 59. 8 65. 2 41% Solvent Ill-59%Tolueuc (Solvent B) 93. 0 81. 5 61. 6 88. l 39% Solvent III+ 61% Toluene. 87. 1 76.0 47. 0 75. 2 Solvnet IV 8O 68. 0 55. 8 65. 0 Solvent V 90. 9 66. 8 52. 1 74. 1 Solvent VI 34. 6 63. 2 24. 8 75. 0

1 Includes toluene as aromatic.

These experiments were conducted in sandstone cores in the same manner as before. The other solvents, except Solvent VI, have at least aromaticity. All of these solvent contain components such as contained in Solvent I and Solvent II. For example, Solvent III contains by volume about 7% benzenes, 8% indanes, 2% indenes, and 31% naphthalenes.

The toluene is used to adjust the viscosity of the aromatic solvents (I, II, or III, etc.) to about 1 cp. Other aromatics such as benzene, xylene, etc., could be used for this purpose.

Other oxygenated compounds that might be used instead of the alcohols described herein are ketones such as methyl ethyl ketone, diethyl ketone, methyl isopropyl ketone, and acids such as glacial propionic and glacial isobutionic acids.

Having fully described the nature, operation, advantages, and objects of our invention, we claim:

1. A method for recovering oil from a subsurface oil reservoir comprising the steps of:

introducing into said reservoir a prefiood bank of carbonated water followed, in succession, by a bank of aromatic hydrocarbon solvent miscible with said oil and a bank of oxygenated hydrocarbon, miscible with said aromatic hydrocarbon and said water; and introducing driving water behind said banks. 2. A method as recited in calim 1 in which said prefiood bank of carbonated water and said driving water each contains 2 to 3 percent by weight salts.

3. A method as recited in claim 2 in which said prefioodwater bank is saturated with an excess of carbon dioxide at the temperature and pressure at the reservoir face in the well bore.

4. A method as recited in claim 1 in which said bank of prefioodwater is saturated with an excess of carbon dioxide at the temperature and pressure at the reservoir face in the well bore.

5. A method for recovering oil from a subsurface oil reservoir comprising the steps of:

introducing into said reservoir through an input well a bank of carbonated water;

introducing into said reservoir behind said bank of carbonated water a bank of aromatic hydrocarbon solvent containing a high percent aromaticity and adjusted to a viscosity of about 1 cp.;

introducing into said reservoir behind said bank of aromatic hydrocarbon solvent a bank of oxygenated hydrocarbon and carbon dioxide adjusted to a viscosity of about 1 cp.; and

introducing into said reservoir behind said oxygenated hydrocarbon bank a driving Water to displace said bank to a producing well and producing reservoir fluids through said producing well.

6. A method as recited in claim 5 in which said oxygenated hydrocarbon bank is employed in the lowest concentration that will achieve the greatest region of miscibility between the oil, aromatic hydrocarbon solvent, oxygenated hydrocarbon, and water phases.

7. A method as recited in claim in which said prefloodwater bank and said driving water contain about 2 to 3 percent by weight salts.

8. A method as recited in claim 7 in which said prefloodwater is saturated with an excess of carbon dioxide at the temperature and pressure at the reservoir face in the well bore.

9. A method as recited in claim 5 in which said prefloodwater is saturated with an excess of carbon dioxide at the temperature and pressure at the reservoir face in the well bore.

10. -A method for recovering oil from a subsurface oil reservoir comprising the steps of:

introducing into said reservoir through an input well a bank of carbonated water;

introducing into said reservoir behind said bank of carbonated water a bank of aromatic hydrocarbon solvent containing over 80% aromaticity and adjusted to a viscosity of about 1 cp., said aromatic solvent comprising a mixture of about 46% toluene and 54% of a refinery by-product extract containing about 30% benzenes, 25% indanes, 30% naphthalenes and 2% tetrahydrophenanthrenes; introducing into said reservoir behind said bank of aromatic hydrocarbon solvent a bank of isopropyl alcohol and carbon dioxide, said carbon dioxide being in an amount sufficient to control the viscosity of said isopropyl alcohol to about 1 cp.; and introducing into said reservoir behind s-aid isopropyl alcohol and CO bank mixture, at driving water to displace said banks to a producing well and then producing reservoir fluids through said producing well.

11. A method as recited in claim 10 in which said isopropyl alcohol is employed in the lowest concentration at which the greatest region of miscibility between the oil, aromatic solvent, isopropyl alcohol and water phases 10 is achieved compatible with maintaining a viscosity of 1 op.

12. A method as recited in claim 10 in which said prefioodwater bank and driving water contain about 2 to 3% by weight salts.

13. A method as recited in claim 12 in which said prefloodwater is saturated with an excess of carbon dioxide at the temperature and pressure at the reservoir face in the well bore.

14. A method as recited in claim 13 in which carbon dioxide is introduced into said reservoir solely in said preflood water bank.

15. A method for recovering oil from a subsurface oil reservoir comprising the steps of:

introducing into said reservoir a preflood bank of water containing 23% by weight salts followed, in succession, by a bank of aromatic hydrocarbon solvent miscible with said oil and a bank of oxygenated hydrocarbon and carbon dioxide adjusted to a viscosity of about 1 cp.; and

introducing into said reservoir behind said oxygenated hydrocarbon bank a driving water containing 23% by weight salts to displace said bank to a producing well and producing reservoir fluids through said producing well.

References Cited UNITED STATES PATENTS 2,875,831 3/1959 Martin et al. 1669 3,003,554 10/1961 Craig et a1. 1669 3,065,790 11/1962 Holrn 166-9 3,102,587 9/1963 Holbrook et a1. 1669 CHARIJES E. OCONNELL, Primary Examiner.

I. A. CALVERT, Assistant Examiner. 

